Frequently "gas wells" produce over several zones. These zones may be separated by tens of feet or by a thousand or more feet. In fact, a half dozen or more production zones may exist for a given well.
The production output of gas and liquid at the surface, in units such as standard cubic feet per day or barrels per day, should be known for each well. Owners, however, frequently also want to know the gas/liquid well profile". This "gas/liquid well profile" indicates the fractional contribution of gas and/or liquid contributed by each production interval. The information is helpful, for instance, in determining whether to open a similar production interval at a given level in a subsequent or adjacent well, or in determining whether to work-over an existing well at certain production levels.
In general, intervals that produce primarily water are not desirable. Intervals that produce the highest percentage of the gas are of the most interest to the owner.
The "gas wells" to which this invention particularly relates produce combined gas and liquid. The liquid is expected to be predominately water or predominately oil. Lower portions of these wells may produce gas percolating through a column of stagnant water. Such a possibility should be taken into account by accurate and sensitive methods for profiling gas wells.
Reasonably accurate and sensitive "quantitative" methods for single phase well profiling are known in the industry. A single phase well produces only gas, only oil, or only water.
Suggestions for improving methods for single phase profiling where gas is produced by percolation through stagnant water, a special case of single phase production, have also been taught. An example of such is discussed below.
"Quantitative" methods for oil/water well profiling are also known in the industry. These methods are discussed below.
"Qualitative" methods are presently being utilized in the industry for profiling combined gas/liquid producing wells. The drawback of the "qualitative" approach is that it lacks the degree of discrimination desired by owners to effectively evaluate completions and manage reservoirs. There is a need, therefore, for sensitive and accurate "quantitative" methods for profiling combined gas/liquid producing wells.
It is believed that the direction that the industry is taking to "quantitatively" solve the problem of gas/liquid well profiling is to develop precise analytical models. The present invention, in contrast to the precise analytical approach, teaches a "quantitative" interpretive method for combined gas/liquid well profiling. The method avoids developing sophisticated analytical models. Rather, it teaches the use of non-in situ calibration data in combination with an interpretive scheme. The results of the method correlate unexpectedly well with the results of the best "qualitative" methods.
To review the prior art in more detail, Thomas O. Allen and Alan P. Roberts summarize and teach, in Vol. II of Production Operations, "Well Completions Workover and Stimulation", the current art of known instruments and methods for single phase and multi-phase well profiling. As pointed out by Allen and Roberts, when dealing with single phase production, or with dual phase combined production of oil and water, certain assumptions and simplifications can be made in regard to downhole conditions. Given readings of a downhole density measuring instrument, a downhole flow rate measuring instrument and proper "in situ" calibration, these assumptions and simplifications permit a "quantitative" analytical solution for profiling single phase production and dual phase oil/water production.
FIG. 1 helps to illustrate the analytic art of oil/water well profiling. Noted upon FIG. 1 are the relationships among flow rate, q; water hold-up, y; and velocity, v. Illustrated therein is a volume of fluid in a pipe P, having a cross-sectional area A, wherein a portion of the fluid comprises water W and a portion of the fluid comprises oil O. The term "water cut" refers to the fraction of water in the total flow stream moving past a particular depth in the well bore in a given time period. Water cut, thus, equals q.sub.w /q.sub.t, the flow rate of water divided by total fluid flow rate. "Water holdup", y.sub.w (sometimes referred to herein as H.sub.w), represents the fraction of water in a total volume of fluid at a particular level. Assuming that one has a value for the downhole density of the oil, .rho..sub.0, and water, .rho..sub.w, such as from measurements of the fluid densities with the well shut in, and that the apparent fluid density .rho..sub.t can be determined by a density measuring instrument at various depths, water holdup, y.sub.w, can be calculated at various levels as: ##EQU1##
Slippage velocity, v.sub.s, is the difference between the oil stream velocity, v.sub.0, and the water stream velocity, v.sub.w .multidot.v.sub.s =v.sub.0 -v.sub.w. Slippage velocity can be determined empirically for oil/water production by knowing the difference in density between oil and water and the water holdup.
FIG. 1 relates the flow rates of water and oil to water holdup and slippage velocity. With these factors, and with a measurement of the rate of the total flow, q.sub.t, by an appropriate flow meter instrument, the oil flow rate q.sub.0 and water flow rate q.sub.w moving by a particular level can be quantitatively determined by the following formulas: EQU q.sub.0 =(1-y.sub.w)(q.sub.t +v.sub.s Ay.sub.w) EQU q.sub.w =y.sub.w [q.sub.t =Av.sub.s (1-y.sub.w)]
Water cut can be determined at that level from the equation water cut equals q.sub.w /q.sub.t. Utilizing such equations, zones contributing water can be "quantitatively" identified.
It is tacitly recognized by Allen and Roberts that the above analytic "quantitative" method for profiling the combined production of oil and water does not work per se for the combined production of gas and liquid. One reason for this is that the density of gas downhole, as contrasted with oil, is clearly a function of the pressure and temperature and should vary with depth. Slippage velocity can not be reliably determined empirically. Computing the downhole slip velocity should require knowing the densities of the fluids at that point. To recite what was stated above, to solve this problem it is believed that the industry is experimenting with a complex simulation model that takes into account dynamic downhole conditions and solves, analytically, for slip velocity in gas/liquid producing wells.
What Allen and Roberts do specifically make reference to, when treating multiphase fluid movement that includes gas, is the common practice in the art today of utilizing "qualitative" techniques. For "gas" wells, Allen and Roberts teach that .downhole moving temperature logs and moving density logs are "read" by experts who predict, based upon their experience and expertise, entry of gas and/or liquid at certain production levels. An example is offered of an evaluation of a gas well completion using such "qualitative" methods.
In the 1991 publication "Profiling Gas-Water Flows in Deviated Pipe", N. R. Carlson has shown, for combined air/water flow in test equipment (air at ambient temperature and atmospheric pressure and water selected from the municipal water supply), that measured flow meter instrument readings (in spinner revolutions per second, or counts per second) vary with total fluid flow rate and "water cut." Carlson also shows how density instrument readings (presented as water holdup readings) vary with the variation in total flow rate and water cut. Carlson demonstrates the accuracy of an interpretive method when applied to surface data for interpolating from known data for the instruments to estimated values for water cut and total flow rate corresponding to new measurements.
Carlson does not teach, in the 1991 article, a protocol for adapting the interpretive method to downhole measurements in order to perform gas/liquid well profiling. The article does not teach or suggest how to adapt the scheme to profiling when one expects to encounter non-linear variations in temperature, pressure, density and slip velocity for combined gas and liquid production.
In a mid-1992 article, Production Logging Applications in Reservoir Management, Norman R. Carlson and R. M. McKinley discuss an example of profiling gas flow through stagnant water. This comprises a special case of single phase production and suggests a benefit from the use of calibration data (as opposed to linear assumptions) when dealing with flow meter readings in gas production. Linear assumptions may be too inaccurate, for the special case of gas percolating through stagnant water. Typically, in single phase production, the readings of a flow meter are analyzed linearly: e.g., the revolutions per second (RPS) of the flow meter spinner above an interval minus the RPS of the spinner below the interval, divided by the RPS of the flow meter above all production levels, is taken to yield an approximation of the fractional contribution by the interval of the fluid being produced. The 1992 article shows that calibrating the downhole readings with a previously non in-situ generated non-linear RPS-to-gas-flow-rate curve for water cut=0 appears to yield profiles that correlate more closely with predictions based upon a moving temperature log.
Proposing a more sensitive and accurate method for predicting gas contributed by intervals where the gas percolates through stagnant water does not solve the dynamic interaction problems involved in quantitatively profiling combined production of gas and liquid. Only a single instrument, for instance, is needed to profile single phase production, including the percolating gas problem. Therefore, the 1992 article does not teach or suggest a sensitive and accurate "quantitative" method for profiling combined gas/liquid production.